2.1. Introduction
Greenhouse gas and acid gas (AG) emissions (CO2, SOx, NOx, H2S, COS, CS2) from power generation or other industrial processes are a huge problem globally. Many different approaches are being explored to recover such gases from combustion or other sources. The significant reduction of carbon dioxide (CO2) emissions from existing and new, upcoming coal-fired power plants presents an enormous opportunity for mitigating greenhouse gas emissions and ultimately global climate change. In the United States, approximately 50% of the electrical power generation capacity comes from coal-fired power plants, which contribute to approximately 80% of CO2 emissions from electrical power generation and roughly 36% of total CO2 emissions. Annual Energy Outlook, DOE/EIA-0383. 2009. Therefore, development of technologies that cost-effectively reduce CO2 emissions from coal-fired power plants is very important to retaining coal-fired power plants within a power generation portfolio especially if climate change regulations are enacted.
Currently, conventional CO2 capture technologies, using aqueous systems such as alkyl amines, e.g., aqueous-monoethanolamine (MEA) based solvent systems, are prohibitively expensive and if implemented could result in a 75 to 100% increase in the cost of electricity (ICOE) for consumers. Existing Plants, Emissions and Capture—Setting CO2 Program Goals, DOE/NETL-1366. 2009. Major contributors to the high ICOE with the conventional capture technologies is the high parasitic power load associated with releasing CO2 from the solvent during solvent regeneration and the high capital costs associated with the scale and materials of construction of the process equipment.
1.1. Water Balancing in Non-Aqueous Solvent (NAS) Acid Gas Removal Systems
Work in non-aqueous solvent (NAS) acid gas (AG) recovery methods include publications from Heldebrandt et al., U.S. Pat. Pub. Nos. US 2009/0136402, US 2009/0220397 and PCT Intl. Pub. No. WO 2009/097317 which disclose reversible AG binding organic liquid systems. These systems permit separation and capture of one or more of several acid gases from a mixed gas stream, transport of the liquid, release of the AGs from the ionic liquid, and reuse of the liquid. They disclose various AG Binding Organic Liquids (BOLs), e.g., NO2BOLs, SO2BOLs, or CO2BOLs.
Wang et al. disclose CO2 capture reagents with superbase-derived protic ionic liquids (PILs). Wang et al. 2010 Angew Chem Int Ed 49 5978-5981. They disclose acid gas absorbing PILs which comprise a superbase and weak proton donors (fluorinated alcohols, imidazoles, pyrrolidinones, phenols) to form liquid carbonates, carbamates, or phenolic salts on reaction with CO2.
Lail et al., PCT Intl. Pub. No. WO 2012/031274 discloses AG removal solvent systems with ionic liquids formed with acid components (fluorinated alcohols) and nitrogenous bases (amines, amidines or guanidines).
Lail et al., PCT Intl. Pub. No. WO 2012/031281 discloses AG removal solvent systems with a diluent and nitrogenous bases (amines, amidines or guanidines).
Bara, U.S. Pat. No. 8,506,914 B2 discloses a CO2 removing solvent comprising of an N-functionalized imidazole and an amine.
Davis and Perry, US 2013/0052109 A1 discloses a CO2 absorbent composition containing a liquid, non-aqueous, silicon-based material, functionalized with one or more groups that reversibly react with CO2 and/or have a high-affinity for CO2; and at least one amino alcohol compound.
In general, water balancing in CO2 capture processes and AG scrubbing processes is maintaining the desired water content of the solvent by controlling the rates of water accumulation and evaporation to avoid both (i) diluting the solvent and flooding the process or (ii) concentrating the solvent and starving the process of water. Water balancing in AG removal processes is also desirable because many processes are an open systems and water is typically introduced to the system via the feed gas and leaves the system via numerous pathways specific to the process typically including the treated gas, the AG product stream, and aqueous contaminant purging streams. At some times it is preferable to operate the process in a manner that maintains the overall water content at or near optimal concentrations. Numerous approaches to maintaining a water balance in aqueous amine-based CO2 capture processes have been developed and industrially implemented for over 60 years.
Water is introduced to the AG process via the feed gas stream and specifically for CO2 removal processes via the flue gas stream. Water can exit the system via numerous streams including the treated gas, the regenerator off-gas, or as a purged liquid water stream. The flue gas stream from a typical 550 MWe supercritical pulverized coal (SCPC) boiler power plant equipped with a wet flue gas desulfurization (wFGD) unit will contain approximately 502,000 lb/h of water as it is saturated at ˜56.7° C. (˜16.7 vol %) [DOE-NETL-2010/1397]. For many CO2 removal processes, it is envisioned that this flue gas stream will be further desulfurized to <10 ppm via a deep sulfur scrubber using NaOH. Deep SO2 scrubbing is described as working optimally at ˜40° C. and therefore the flue gas temperature and water content will be concomitantly reduced. Reducing the temperature of the flue gas stream to 40° C. lowers the water content to 7.38% and thus the amount of water entering the CO2 absorber in the flue gas stream is reduced from ˜502,000 lb/h to 222,000 lb/h. In order for water accumulation in the solvent/process not to be an issue, it must either be condensed or adsorbed/absorbed by the solvent.
For the AG removal process to have a neutral water balance, the same amount of water must leave the process as enters on a time-averaged basis. Water balancing is a necessary consideration for all AG scrubbing processes including CO2 removal processes and processes that utilize aqueous- and non-aqueous-based solvents. Numerous methods/approaches to addressing this operational issue have been developed and employed for decades. The most commonly practiced approaches to controlling water content in AG removal processes have been described by Kvamsdal et al. 2010 Int J Greenhouse Gas Contr 4 613-620, and typically include: (i) flue gas temperature, absorber inlet and outlet; (ii) temperature profile within the absorption section of the absorber; (iii) absorber inlet lean amine temperature specification; and (iv) washing sections in the top of the absorber and desorber. In order to balance the water in CO2 removal processes, Kvamsdal et al. suggests the following: (i) precooling the flue gas prior to the absorption column; (ii) water recycling; and (iii) gas cooling on leaving the absorption column.
In a non-aqueous solvent (NAS)-based AG removal process, water can also be introduced to the system via the feed gas stream, e.g., a combustion flue gas. However, maintaining a water balance in a NAS process can be complicated due to the non-aqueous, i.e., non-water based, nature of the AG selective solvent. Water in the feed gas can be condensed by contact with a colder NAS stream, e.g., in the absorber, and if water has a measureable solubility in the NAS than it can be adsorbed or stripped by the NAS. As such, water can be present in the NAS process as water soluble in the NAS and as a separate water-rich phase with the distribution depending upon the solubility of water in the NAS. Due to the low water miscibility of NASs, the prospect of forming a separate, water-rich phase in a NAS AG removal process is high. The formation of a bi-phasic NAS-rich/water-rich mixture in a NAS AG removal process represents significant processing and operating challenges.
Recently, Katz et al., U.S. Pat. Pub. No. US 2013/0230440 discloses a theoretical mechanical process for removing AGs from water containing streams such combustion exhaust gases and water separation/recovery. Initially water in the fluid stream is either condensed or dissolved in the acid gas absorption liquid and is accumulated as a separate aqueous phase. The accumulation of water in NAS creates a bi-phasic system consisting of a water-rich and a non-aqueous-rich phase and the water-rich phase would be separated from the non-aqueous solvent-rich phase via mechanical separation to sustain the process operability and stability. The condensed water or aqueous phase is removed by decanting and/or centrifuging. The removed water is then brought in contact with the treated gas stream to rehydrate the treated gas.
Several shortcomings of Katz et al., U.S. Pat. Pub. No. US 2013/0230440 are apparent. First, this approach requires the formation of a bi-phasic solvent that can be separated via mechanical separation. Second, due to the scale of the process, the size of the liquid decanter will be very large and will greatly increase the capital expense of the process. Third, the process operation will become more complicated due to the additional complexity of an added decanter system. Fourth, achieving a neutral water balance by rehydrating the treated gas in a rehydration zone will require the addition of heat increasing the energy demand for the process.